In the oil and gas industry, geophysical survey techniques are commonly used to aid in the search for and evaluation of subterranean hydrocarbon or other mineral deposits. Generally, a seismic energy source, or “source,” generates a seismic signal that propagates into the earth and is partially reflected and refracted by subsurface seismic interfaces between underground formations having different acoustic impedances. The reflections are recorded by seismic detectors, or “receivers,” located at or near the surface of the earth, in a body of water, or at known depths in boreholes, and the resulting seismic data can be processed to yield information relating to the location and physical properties of the subsurface formations. Seismic data acquisition and processing generates a profile, or image, of the geophysical structure under the earth's surface. While this profile does not provide an accurate location for oil and gas reservoirs, it suggests, to those trained in the field, the presence or absence of them.
Various sources of seismic energy have been used to impart the seismic waves into the earth. Such sources have included two general types: 1) impulsive energy sources and 2) seismic vibrator sources. The first type of geophysical prospecting utilizes an impulsive energy source, such as dynamite or a marine air gun, to generate the seismic signal. With an impulsive energy source, a large amount of energy is injected into the earth in a very short period of time. In the second type of geophysical prospecting, a vibrator is used to propagate energy signals over an extended period of time, as opposed to the near instantaneous energy provided by impulsive sources. Except where expressly stated herein, “source” is intended to encompass any seismic source implementation, both impulse and vibratory, including any dry land or marine implementations thereof.
The seismic signal is emitted in the form of a wave that is reflected and refracted off interfaces between geological layers. The reflected and refracted waves are received by an array of geophones, or receivers, located at the earth's surface, which convert the displacement of the ground resulting from the propagation of the waves into an electrical signal recorded by means of recording equipment. The receivers typically receive data during the source's energy emission and during a subsequent “listening” interval. The recording equipment records the time at which each reflected and refracted wave is received. The seismic travel time from source to receiver, along with the velocity of the source wave, can be used to reconstruct the path of the waves to create an image of the subsurface. A large amount of data may be recorded by the recording equipment and the recorded signals may be subjected to signal processing before the data is ready for interpretation. The recorded seismic data may be processed to yield information relating to the location of the subsurface reflectors and the physical properties of the subsurface formations. That information is then used to generate an image of the subsurface.
In some locations, oil reservoirs are made up of heavy oil. Heavy oil is oil that is difficult to recover in its natural state through ordinary oil production methods. Heat or dilution may be used to assist in recovering heavy oil. In other locations, an oil reservoir may consist of an oil sand. Oil sand is a mixture of sand, water, clay, and oil crude bitumen (a thick, viscous, and sticky form of crude oil). Heat and dilution may be used to separate the oil crude bitumen from the sand, clay, and water to produce oil for refining. For both heavy oil and oil sand, steam is often used to provide heat and dilution. Steam may be injected into a wellbore to reduce viscosity and increase mobility of heavy oil in the reservoir. In some locations, steam, water, solvent, polymer or other suitable type of material may be used to displace the residual oil and gas remaining in the reservoir and improve the flow between oil, gas, and rock to increase the oil recovery ratio. These oil recovery methods, commonly called secondary or tertiary recovery methods contrast with primary oil recovery methods where only natural pressure is used to push crude oil to the surface.
Oil reservoirs, where production is stimulated through the use of injections of steam, water, solvent, polymer, or other suitable type of material, may be continuously surveyed to provide real-time monitoring of the reservoir. A continuous seismic monitoring system may consist of an array of receivers located near the reservoir and one or more sources. The sources continuously operate to emit a seismic signal. The receivers receive the reflected and refracted signal, which is recorded by recording equipment to determine the changes in the earth's subsurface and the reservoir over time.
A continuous seismic monitoring system may be used to track the location of fronts associated with the injection. A front is a discontinuous and extended area forming a contact zone between two regions of the reservoir that have different physical properties, for example temperature, pressure, or saturation. In a geological context, the physical properties of one or more regions of the reservoir, located under the earth's surface, may have changed directly or indirectly due to the injection. The physical width of a given front due to a given injection will depend on various factors, such as the geology and the properties of the monitored reservoir. A front will propagate through the reservoir as the effects of the injection move through the subsurface. A front may travel at different speeds through different types of subsurface geology. The front propagation velocity of each type of front may depend on the static reservoir properties, such as the pressure, temperature, saturation, and/or viscosity of the reservoir. It may take days or weeks for a front to arrive at a particular location in and around a reservoir.
A front may be a pressure front, a temperature front, a water front, a steam front, or any other suitable type of front. A pressure front indicates the boundary where the pressure of the subsurface has been changed due to the injection and/or the oil and water production. A temperature front indicates the boundary where the temperature of the subsurface has been changed by the injection. A water front or steam front indicates the boundary where the water or steam saturation of the subsurface has been changed by the injection. The fronts may not arrive at a location simultaneously. Generally, for a given injection, the pressure front travels faster than the temperature front, the water front, or the steam front. Generally for a steam injection, the temperature front travels faster than the water front and steam front.
Data gathered from a continuous seismic monitoring system may be used to determine a seismic attribute. A seismic attribute is a data point that can be extracted or derived from seismic data. The seismic data can be measured seismic data or computed synthetic data from a model of the reservoir. Seismic travel time and seismic amplitude are two examples of seismic attributes. Where seismic attributes are derived on repeated seismic surveys or continuous monitoring seismic surveys, the seismic attributes may be referred to as “time-lapse seismic attributes.”
Seismic data can be used to identify areas of the reservoir that have not yet been stimulated by an injection and to optimize the location for well placement of future injector wells or production wells. However, seismic data may not provide data for making predictions of the front arrival time or provide data to establish warnings based on early detection of a front. Thus, it would be useful to provide systems and methods that predict the front arrival time in seismic monitoring.